Crude oils typically contain naphthenic acids to a varying degree, and the quantity of naphthenic acids predominantly depends on the particular formation from which they are obtained. For example, crude oils from California, Venezuela, North Sea, Western Africa, India, China, and Russia have often an undesirably high naphthenic acid content. Naphthenic acid and sulfur compounds in such crudes are often correlated with corrosion in crude and vacuum units and are generally thought to contribute to premature equipment failure of such units. Therefore, numerous approaches have been made to control or reduce naphthenic acid corrosion (NAC).
However, empirical data correlating naphthenic acid content and corrosivity are notoriously inconsistent due to several factors. Among other things, naphthenic acids encompass numerous chemically diverse species of carboxylic acids, and in most cases the qualitative and quantitative chemical composition, boiling point distribution, and decomposition temperature of naphthenic acid will directly influence corrosion rates in crude and vacuum units. For example, naphthenic acids typically include compounds of the general formula R—COOH where R comprises a substituted or unsubstituted alkyl, cycloalkyl, or aryl (each of which may have a varying degree of saturation). In most cases, naphthenic acids include as a common component compounds of the formula R(CH2)nCOOH in which R is a phenyl (or other unsaturated or partially saturated cycloalkyl or cycloaryl) ring and n is frequently between 1 and 12. Still further, naphthenic acids may additionally include non-carbon groups such as sulfur- or nitrogen-containing groups.
To complicate matters even further, there are numerous methods for quantification of naphthenic acids, most of which typically fail to provide consistent results. For example, the ASTM procedures for determination of Total Acid Number (TAN) are often sensitive to compounds commonly found in crudes (e.g., ASTM D974 or ASTM D664). Furthermore, these ASTM methods typically fail to differentiate between naphthenic acids, phenols, and other acids, organic and inorganic, present in the crude.
Other known procedures require removal of sulfurous compounds (sulfur tends to influence naphthenic acid corrosion) to provide analysis of the TAN number, such as UOP 565 (a potentiometric method), or UOP 587 (a colorimetric method). While such procedures typically provide at least some meaningful analysis of the sample under investigation, the influence of sulfur in the crude on the corrosivity can only be estimated as the sulfur is removed prior to analysis.
Evaluation of corrosivity is primarily by a classical model considering Total Acid Number (TAN), with TAN assigned based on milligrams of KOH required to neutralize a one gram sample of crude. If TAN is greater than 0.5 in feedstock or greater than 1.5 in side streams, a crude is commonly considered corrosive. Therefore, various refiners protect their plants by blending high naphthenic acid crudes with low acid crudes to a predetermined TAN number (e.g., below 0.5 for crudes or 1.5 for cuts), or by avoiding refining of crudes suspected of having relatively high quantities of naphthenic acids. Alternatively, the equipment may be constructed using corrosion resistant alloys (e.g., Mo-stainless steel), which substantially increases the cost, or corrosion inhibitors may be added, which has other disadvantages. Unfortunately, about 10-20% of the global crudes are now considered as having relatively high naphthenic acid content, and are therefore problematic to sell to refiners. Consequently, there is an unsatisfied need for improved compositions, configurations, and methods of reducing naphthenic acid corrosivity in hydrocarbon materials, and especially in crudes.